1. Field of the Invention
Embodiments disclosed herein relate generally to methods and systems for the offshore thermal treatment and disposal of drill cuttings.
2. Background Art
When drilling or completing wells in earth formations, various fluids (“well fluids”) are typically used in the well for a variety of reasons. Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroleum bearing formation), transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, implacing a packer fluid, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
As stated above, one use of well fluids is the removal of rock particles (“cuttings”) from the formation being drilled. However, because of the oil content in the recovered cuttings, particularly when the drilling fluid is oil-based or hydrocarbon-based, the cuttings are an environmentally hazardous material, making disposal a problem. That is, the oil from the drilling fluid (as well as any oil from the formation) becomes associated with or adsorbed to the surfaces of the cuttings.
A variety of methods have been proposed to remove adsorbed hydrocarbons from the cuttings. U.S. Pat. No. 5,968,370 discloses one such method which includes applying a treatment fluid to the contaminated cuttings. The treatment fluid includes water, a silicate, a nonionic surfactant, an anionic surfactant, a phosphate builder and a caustic compound. The treatment fluid is then contacted with, and preferably mixed thoroughly with, the contaminated cuttings for a time sufficient to remove the hydrocarbons from at least some of the solid particles. The treatment fluid causes the hydrocarbons to be desorbed and otherwise disassociated from the solid particles.
Furthermore, the hydrocarbons then form a separate homogenous layer from the treatment fluid and any aqueous component. The hydrocarbons are then separated from the treatment fluid and from the solid particles in a separation step, e.g., by skimming. The hydrocarbons are then recovered, and the treatment fluid is recycled by applying the treatment fluid to additional contaminated sludge. The solvent must be processed separately.
Some prior art systems use low-temperature thermal desorption as a means for removing hydrocarbons from extracted soils. Generally speaking, low-temperature thermal desorption (LTTD) is an ex-situ remedial technology that uses heat to physically separate hydrocarbons from excavated soils. Thermal desorbers are designed to heat soils to temperatures sufficient to cause hydrocarbons to volatilize and desorb (physically separate) from the soil. Typically, in prior art systems, some pre- and post-processing of the excavated soil is required when using LTTD. In particular, cuttings are first screened to remove large cuttings (e.g., cuttings that are greater than 2 inches in diameter). These cuttings may be sized (i.e., crushed or shredded) and then introduced back into a feed material. After leaving the desorber, soils are cooled, re-moistened, and stabilized (as necessary) to prepare them for disposal/reuse.
U.S. Pat. No. 5,127,343 (the '343 patent) discloses one prior art apparatus for the low-temperature thermal desorption of hydrocarbons. FIG. 1 from the '343 patent reveals that the apparatus consists of three main parts: a soil treating vessel, a bank of heaters, and a vacuum and gas discharge system. The soil treating vessel is a rectangularly shaped receptacle. The bottom wall of the soil treating vessel has a plurality of vacuum chambers, and each vacuum chamber has an elongated vacuum tube positioned inside. The vacuum tube is surrounded by pea gravel, which traps dirt particles and prevents them from entering a vacuum pump attached to the vacuum tube.
The bank of heaters has a plurality of downwardly directed infrared heaters, which are closely spaced to thoroughly heat the entire surface of soil when the heaters are on. The apparatus functions by heating the soil both radiantly and conventionally, and a vacuum is then pulled through tubes at a point furthest away from the heaters. This vacuum both draws the convection heat (formed by the excitation of the molecules from the infrared radiation) throughout the soil and reduces the vapor pressure within the treatment chamber. Lowering the vapor pressure decreases the boiling point of the hydrocarbons, causing the hydrocarbons to volatize at much lower temperatures than normal. The vacuum then removes the vapors and exhausts them through an exhaust stack, which may include a condenser or a catalytic converter.
Hammermill processes are often also used to recover hydrocarbons from a solid. In the typical hammermill process, the friction principle is used to generate sufficient energy for the oil fractions to be evaporated off. Specifically, a hammer mill with swinging rotor arms are used to finely crush all the particles, which results in the generation of heat, and allows for the evaporation of the oil in the material at a temperature lower than normal evaporation.
U.S. Patent Publication No. 2004/0149395 discloses a rotomill process, based on the hammermill technology, by which adsorbed oil may be evaporated at a temperature lower than its atmospheric boiling point. The presence of a vapor phase of a second component (typically water) allows for a substantial reduction in the partial pressure of the hydrocarbons, and thus a decrease in their boiling point.
Thermal desorption units are typically set up as fixed, land-based installation due to the off shore limitations associated with size, weight, and processing capacity. Thus, to avoid contamination by oil-coated drill cuttings, cuttings are typically transported onshore for processing.
Further complicating the treatment of drill cuttings, when a wellbore fluid brings cuttings to the surface, the mixture is typically subjected to various mechanical treatments (shakers, centrifuges, etc) to separate the cuttings from the recyclable wellbore fluid. However, the separated drill cuttings, which still possess a certain portion of oil from the wellbore fluid absorbed thereto, are in the form of a very thick heavy paste, creating difficulties in handling and transportation. Thus, frequently, in offshore applications, the thick drill cuttings paste is slurrified with a carrier fluid, typically an oil-based fluid, to allow for ease in pumping and handling the drill cuttings paste.
Traditional methods of disposing the drill cuttings include dumping, bucket transport, conveyor belts, screw conveyors, and washing techniques that require large amounts of water. Adding water creates additional problems of added volume and bulk, pollution, and transport problems. Installing conveyors requires major modification to the rig area and involves extensive installation hours and expense. In some instances, the cuttings, which are still contaminated with some oil, are transported from a drilling rig to an offshore rig or ashore in the form of a thick heavy paste or slurry for injection into an earth formation. Typically, the material is put into special skips of about 10 ton capacity that are loaded by crane from the rig onto supply boats. This is a difficult and dangerous operation that may be laborious and expensive.
Another method of disposal includes returning the drill cuttings, drilling mud, and/or other waste via injection under high pressure into an earth formation. Generally, the injection process involves the preparation of a slurry within surface-based equipment and pumping the slurry into a well that extends relatively deep underground into a receiving stratum or adequate formation. The basic steps in the process include the identification of an appropriate stratum or formation for the injection; preparing an appropriate injection well; formulation of the slurry, which includes considering such factors as weight, solids content, pH, gels, etc.; performing the injection operations, which includes determining and monitoring pump rates such as volume per unit time and pressure; and capping the well.
A slurrification system is used to create a slurry for a cuttings re-injection system. Typically, slurrification systems receive cuttings and convert them into a pumpable slurry. Elements of a slurrification system generally include a fine-solids (“fines”) tank, a coarse-solids (“coarse”) tank, a classification system, and a storage vessel, wherein drill cuttings are dried, separated, and transferred to a cuttings re-injection system or stored for further processing. After preparation of the slurry, the slurry is pumped to a storage vessel, until an injection pump is used to pump the slurry down a wellbore.
In operation, attempts to produce a slurry that meet local environmental regulations and operational regulations has proven problematic. Current slurrification systems are operationally inefficient. For example, adjustments to the drilling operation including adjustments to cuttings volume production and rate of penetration of the wellbore may cause slurrification process and cuttings re-injection inefficiencies. Moreover, increasingly stringent cuttings-discharge regulations have pressured operators and drilling contractors to reduce drilling waste volumes and recover products for re-use. Thus, there exists a continuing need for more efficient slurrification methods and systems, specifically, for slurrification systems for use in preparing slurries for re-injecting cuttings into a wellbore.
Accordingly, there exists a continuing need for improvements in the offshore treatment and disposal of drill cuttings.